Downhole electromagnetic sensing techniques

ABSTRACT

An electromagnetic (EM) telemetry system includes an EM transmitter configured to transmit EM signals downhole and multiple sensors each configured to communicate with the EM transmitter and with another of the multiple sensors. Each sensor is placed a distance from another sensor along a length of a wellbore in the EM telemetry system. The EM telemetry system also includes a processor configured to select two or more sensors of the multiple sensors based on a signal to noise ratio (SNR) of an EM signal received from the two or more selected sensors, a depth of the EM transmitter, or both.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a continuation application of U.S. patentapplication Ser. No. 16/806,636, filed on Mar. 2, 2020, which is adivisional application of U.S. Pat. No. 10,598,809, filed on Jun. 14,2017, which claims priority to and the benefit of U.S. ProvisionalPatent Application No. 62/357,094, filed on Jun. 30, 2016, the entiretyof both of which are incorporated herein by reference.

BACKGROUND

Conventional electromagnetic (“EM”) telemetry employs two or more stakes(i.e., electrodes) placed in the ground to detect a signal. The signalmay include an electrical current, and the current may cause a voltagedifferential between the stakes due to the resistivity of the ground.The signal includes an EM telemetry portion that is transmitted from adownhole tool in a wellbore. The EM telemetry portion includes encodedmeasurement data captured by the downhole tool. The signal also includesan electrical noise portion due to equipment (e.g., motors, generators,pumps, etc.) at the surface. It is oftentimes difficult to distinguishthe EM telemetry portion of the signal from the electrical noise portionof the signal. To make matters more difficult, the EM telemetry portionof the signal is largely attenuated by the subterranean formationbetween the downhole tool and the stakes at surface. Furthermore, theremay be other EM telemetry tools interfering with the desired signal.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

An electromagnetic (EM) telemetry system includes an EM transmitterconfigured to transmit EM signals downhole and multiple sensors eachconfigured to communicate with the EM transmitter and with another ofthe multiple sensors. Each sensor is placed a distance from anothersensor along a length of a wellbore in the EM telemetry system. The EMtelemetry system also includes a processor configured to select two ormore sensors of the multiple sensors based on a signal to noise ratio(SNR) of an EM signal received from the two or more selected sensors, adepth of the EM transmitter, or both.

In another embodiment, an insulating device configured to electricallyinsulate sensors in an electromagnetic (EM) telemetry system includes afirst conductive sub and a second conductive sub, each comprising athreaded surface configured to fit with the other. The device includesan insulation structure between the first and second conductive subs anda conductor channel disposed across the insulation structure and betweena first electronic pocket in the first conductive sub and a secondelectronic pocket in the second conductive sub. The conductor channel isconfigured to alter the electrical potential of the first sub.

Another embodiment of an insulating device configured to electricallyinsulate sensors in an electromagnetic (EM) telemetry system isdisclosed. The device includes a first conductive sub and a secondconductive sub, each comprising a threaded surface configured to fitwith the other. The device also includes an insulation structure betweenthe first and second conductive subs and a conductor channel disposedthrough the second conductive sub and through the insulation structureand between the first conductive sub and the second conductive sub. Theconductor channel is configured to alter the electrical potential of thefirst conductive sub.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute apart of this specification, illustrate embodiments of the presentteachings and together with the description, serve to explain theprinciples of the present teachings. In the figures:

FIG. 1 illustrates a schematic side view of first and second wellboresin a subterranean formation, according to an embodiment.

FIG. 2 illustrates a schematic view of an amplifier that receivessignals from the first and second sensors, according to an embodiment.

FIG. 3 illustrates a schematic side view of the second wellbore havingthree sensors, according to an embodiment.

FIG. 4 illustrates a schematic side view of a wellsite showing an EMtelemetry tool having dipoles, according to an embodiment.

FIG. 5 illustrates a schematic side view of a wellsite showing an EMtelemetry tool having dipoles, mapped to a schematic diagram of sensorsand gaps, according to an embodiment.

FIG. 6 illustrates a schematic view of an EM sensor, according to anembodiment.

FIG. 7 illustrates a schematic side view of a connection for an EMsensor, according to an embodiment.

FIG. 8 illustrates a schematic side view of a connection for multiple EMsensors, according to an embodiment.

FIG. 9 illustrates a schematic side view of a cantilever arm for an EMsensor, according to an embodiment.

FIG. 10 illustrates a schematic side view of a wellsite showing an EMtelemetry tool having dipoles, mapped to a schematic diagram of sensorsand gaps and a downhole decoder, according to an embodiment.

FIG. 11 illustrates a top schematic view of a wellsite having multipleselectable wells, according to an embodiment.

FIGS. 12-16 and 17A-D illustrate different configurations of insulationgaps in a gap sub for electrically isolating sensors in an EM telemetrysystem, according to an embodiment.

FIG. 18 illustrates a schematic view of a computing system forperforming at least a portion of the methods, according to anembodiment.

DETAILED DESCRIPTION

Reference will now be made in detail to specific embodiments illustratedin the accompanying drawings and figures. In the following detaileddescription, numerous specific details are set forth in order to providea thorough understanding of the disclosure. However, it will be apparentto one of ordinary skill in the art that the disclosure may be practicedwithout these specific details. In other instances, well-known methods,procedures, components, circuits, and networks have not been describedin detail so as not to obscure aspects of the embodiments.

The terminology used in the description herein is for the purpose ofdescribing particular embodiments and is not intended to be limiting. Asused in the description and the appended claims, the singular forms “a,”“an” and “the” are intended to include the plural forms as well, unlessthe context clearly indicates otherwise. It will also be understood thatthe term “and/or” as used herein refers to and encompasses any possiblecombinations of one or more of the associated listed items. It will befurther understood that the terms “includes,” “including,” “comprises”and/or “comprising,” when used in this specification, specify thepresence of stated features, integers, operations, elements, and/orcomponents, but do not preclude the presence or addition of one or moreother features, integers, operations, elements, components, and/orgroups thereof. Further, as used herein, the term “if” may be construedto mean “when” or “upon” or “in response to determining” or “in responseto detecting,” depending on the context.

FIG. 1 illustrates a schematic view of an EM telemetry system 100 in awellsite having a first wellbore 110 and a second wellbore 160 formed ina subterranean formation 104, according to an embodiment. The firstwellbore 110 may have a downhole tool 120 positioned therein. Thedownhole tool 120 may be or include a rotary steerable system (“RSS”)122, a motor 124, one or more logging-while-drilling (“LWD”) tools 126,one or more measurement-while-drilling (“MWD”) tools 128, or acombination thereof. The LWD tool 126 may be configured to measure oneor more formation properties and/or physical properties as the firstwellbore 110 is being drilled or at any time thereafter. The MWD tool128 may be configured to measure one or more physical properties as thefirst wellbore 110 is being drilled or at any time thereafter. Theformation properties may include resistivity, density, porosity, sonicvelocity, gamma rays, and the like. The physical properties may includepressure, temperature, wellbore caliper, wellbore trajectory, aweight-on-bit, torque-on-bit, vibration, shock, stick slip, and thelike. The measurements from the LWD tool 126 may be sent to the MWD tool128. The MWD tool 128 may then group the sets of data from the LWD tool126 and the MWD tool 128 and prepare the data for transmission to thesurface 102.

The data may be transmitted to the surface via electromagnetic (“EM”)telemetry, mud pulse telemetry, or the like. When using EM telemetry totransmit the data from the downhole tool 120 in the first wellbore 110to the surface 102, a coding method is used. For example, apredetermined carrier frequency may be selected and any suitablemodulation method, e.g., phase shift keying (“PSK”), frequency shiftkeying (“FSK”), continuous phase modulation (“CPM”), quadratureamplitude modulation (“QAM”), or orthogonal frequency divisionmultiplexing (“OFDM”), may be used to superpose the bit pattern onto thecarrier wave. In another embodiment, a baseband line code, e.g., pulseposition modulation, Manchester coding, biphase coding, or runlengthlimited codes such as 4b/5b or 8b/10b coding, may be used to superposethe bit pattern onto a waveform suitable for transmission across the MWDchannel. This coded signal is applied as a voltage differential acrossan electrical insulation layer (e.g., ceramic, peek, hard plastic) 130positioned between upper and lower portions of the downhole tool 120.Due to the voltage differential, an EM telemetry signal (e.g.,electrical current) 132 is generated that travels through thesubterranean formation 104. More particularly, the EM telemetry currentdensity signal 132 travels from the lower portion of the downhole tool120, out into the subterranean formation 104, and bends back toward theupper portion of the downhole tool 120, in an almost semi-ellipticallike-shape as determined by the boundary conditions of the subterraneanformation 104. The EM telemetry signal 132 from the downhole tool 120may become attenuated proceeding away from the downhole tool 120 (e.g.,upward toward the surface 102) due to the resistivity of thesubterranean formation 104. More particularly, the EM telemetry signal132 may be attenuated in highly conductive portions of the subterraneanformation 104, which may shunt the EM telemetry signal 132, and/or theEM telemetry signal 132 may be attenuated by highly resistive portionsof the subterranean formation 104, which may restrict the flow of the EMtelemetry signal 132 to the surface 102.

Surface equipment may 140 be positioned at the surface 102. The surfaceequipment 140 may be or include a motor, a generator, a pump, or thelike. The surface equipment 140 may be poorly grounded to one-another,which may introduce noise signals (e.g., electrical current) 142 intothe subterranean formation 104 near the surface 102. The noise signals142 from the surface equipment 140 may become attenuated proceeding awayfrom the surface equipment 140 due to the resistivity of thesubterranean formation 104. Thus, in one example, the noise signals 142from the surface equipment 140 may become more and more attenuatedproceeding downward, deeper into the subterranean formation 104.

In one embodiment, one or more surface sensors (two are shown: 144, 146)may be positioned at the surface 102. The surface sensors 144, 146 maybe or include metallic stakes driven into the surface 102. Although notshown, one of the surface sensors (e.g., sensor 144) may be coupled to ablow-out preventer (“BOP”) of the first wellbore 110. The surfacesensors 144, 146 may measure the EM telemetry signal 132 and the noisesignal 142 in the subterranean formation 104. The signals 132, 142measured by the surface sensors 144, 146 may have an EM telemetryportion (e.g., from the EM telemetry signal 132 transmitted from thedownhole tool 120), and an electrical noise portion (e.g., from thenoise signal 142 generated by the noise-generating equipment 140 at thesurface 102).

The surface sensors 144, 146 may detect/measure the signals 132, 142 inthe subterranean formation 104. A voltage differential may then bedetermined between the surface sensors 144, 146 using the signals 132,142 and the resistance between the surface sensors 144, 146. Theresistance may be due to the resistivity of the subterranean formation104. The resistance between the surface sensors 144, 146 is oftentimesfrom about 25 ohms to about 100 ohms (e.g., about 50 ohms).

The signals 132, 142 (e.g., current or voltage differential) may betransmitted from the surface sensors 144, 146 to a computer system 1000.The signals 132, 142 (e.g., current or voltage differential) received bythe computer system 1000 may include an EM telemetry portion from thedownhole tool 120 and an electrical noise portion from the surfaceequipment 140. The computer system 1000 may identify and decode the EMtelemetry portion to recover the properties measured by the downholetool 120. Both signals 132, 142 may be travelling in asubstantially-horizontal direction proximate to the surface 102 whendetected by the surface sensors 144, 146, causing the electrical noiseportion to be “electrically-coupled” to the EM telemetry portion. Thismay make it difficult to distinguish the EM telemetry portion from theelectrical noise portion.

To improve the signal-to-noise ratio (“SNR”) between the EM telemetryportion and the electrical noise portion, a first sensor 162 may bepositioned in the second wellbore 160. The second wellbore 160 may belaterally-offset from the first wellbore 110 from about 10 m to about100 m, about 100 m to about 500 m, about 500 m to about 1000 m, about1000 m to about 3000 m, or more. The first sensor 162 may be or includean electrode, a magnetometer, a capacitive sensor, a current sensor, aHall-effect sensor, a toroid, a solenoid, a resistive gap, or acombination thereof. The first sensor 162 may be placed in asubstantially vertical portion of the second wellbore 160, a lateralportion of the second wellbore 160, or in the heel therebetween. In oneexample, the first sensor 162 may be placed in a lateral portion of thesecond wellbore 160 that is extending toward the first wellbore 110. Thedepth of the first sensor 162 may be greater than or equal to the depthof the downhole tool 120, as measured vertically from the surface 102;however, in other embodiments, the depth of the first sensor 162 may beless than the depth of the downhole tool 120. A first insulated cable164 may be coupled the first sensor 162. The first cable 164 may beconfigured to transmit the measurements captured by the first sensor 162to the surface 102.

The second wellbore 160 may be “open-hole” or have a casing 166positioned therein. When the second wellbore 160 has the casing 166 (orother metallic tubular member) positioned therein, the first sensor 162may be in contact with the casing 166. In other embodiments, the firstsensor 162 may not be in direct contact with the casing 166 and mayinstead sense the EM telemetry signal 132 through a liquid (e.g. brine)or through other means such as a magnetometer, capacitive coupling, etc.at a point in the second wellbore 160.

At least a portion of the EM telemetry signal 132 from the downhole tool120 in the first wellbore 110 may be measured by the first sensor 162 inthe second wellbore 160. For example, the EM telemetry signal 132 mayflow into the casing 166 in the second wellbore 160, and the firstsensor 162 may measure the EM telemetry signal 132 in the casing 166proximate to the first sensor 162. The measurement data from the firstsensor 162 may be transmitted up to the surface 102 through the cable164 in the second wellbore 160.

Once the EM telemetry signal 132 reaches the casing 166 in the secondwellbore 160, at least a portion of the EM telemetry signal 132 may flowup the casing 166 in the second wellbore 160 toward the surface 102,which is the path of least resistance. A second sensor 168 may beconfigured to measure the EM telemetry signal 132 at a differentlocation than the first sensor 162. As shown, the second sensor 168 ispositioned within the second wellbore 160 and above the first sensor162. In another embodiment, the second sensor 168 may be positioned atthe surface 102 proximate to the top of the second wellbore 160 (e.g.,coupled to a wellhead or BOP of the second wellbore 160). The secondsensor 168 may also be or include an electrode, a magnetometer, acapacitive sensor, a current sensor, a Hall-effect sensor, a toroid, asolenoid, a resistive gap, or a combination thereof. The second sensor168 may be in contact with the casing 166 in the second wellbore 160 orin contact with an intermediate conductive member that is in contactwith the casing 166 in the second wellbore 160, to enable the secondsensor 168 to detect the EM telemetry signal 132 at that location. Asecond insulated cable 170 may be coupled the second sensor 168. Thesecond cable 170 may be configured to transmit the measurements capturedby the second sensor 168 to the surface 102.

As will be appreciated, the EM telemetry signal 132 flowing through thecasing 166 at the location of the first and second sensors 162, 168 maybe different. For example, the EM telemetry signal 132 measured by thesecond sensor 168 may be smaller than the EM telemetry signal 132measured by the first sensor 162 because a portion of the EM telemetrysignal 132 “leaks” back to the downhole tool 120 through thesubterranean formation 104 before reaching the second sensor 168. Thisleaking effect may be more pronounced for casing materials that are lessconductive or where a joint between two casing joints introduces aseries resistance. In addition, the first and second sensors 162, 168may also be affected differently by the noise signals 142 produced bythe surface equipment 140. For example, the noise signals 142 that reachthe first sensor 162 may be smaller than the noise signals 142circulating in proximity to the second sensor 168 due to the additionaldistance (and corresponding resistance) that the noise signal 142travels to reach the first sensor 162. Said another way, as depth of thedownhole tool 120 increases, the amplitude of the noise signals 142 fromthe surface 102 may be reduced due to shunting of the noise currentloops in the conductive formations and attenuation due to interleavedresistive layers.

As the downhole tool 120 drills deeper into the subterranean formation104, the EM telemetry signal 132 transmitted by the downhole tool 120may be attenuated on its path to the surface 102. This attenuation isgreater in highly-conductive formations that shunt the EM telemetrysignal 132 and can be worsened by the presence of highly resistivelayers which restrict the flow of the EM telemetry signal 132 to thesurface 102.

A distance between the first and second sensors 162, 168 may be known.The distance may be, for example, from about 10 m to about 50 m, about50 m to about 100 m, about 100 m to about 250 m, about 250 m to about500 m, about 500 m to about 1000 m, or more. While it was previouslyassumed that the resistance between two points on the casing 166 waszero or close to zero, over larger distances, the resistance is nolonger nominal. As a result, with the distance known, the resistance ofthe casing 166 between the first and second sensors 162, 168 may bedetermined. The resistance may be, for example, from about 0.1 ohms per1000 m to about 5 ohms per 1000 m, from about 0.2 ohms per 1000 m toabout 2 ohms per 1000 m, or from about 0.3 ohms per 1000 m to about 1ohm per 1000 m. In one specific example, the resistance may be about 0.5ohms per 1000 m. Thus, in one example, if there is 10,000 m of casing166 between the first and second sensors 162, 168, the resistance may beabout 5 ohms. At least a portion of the casing 166 may be substantiallyvertical, which may cause the EM telemetry signal 132 to flow in asubstantially vertical direction. As a result, the EM telemetry signal132 from the downhole tool 120 (e.g., the EM telemetry portion) may besubstantially perpendicular to the noise signal 142 from the surfaceequipment 140 at the surface 102 (e.g., the electrical noise portion),which may reduce the electrical coupling between the two portions.

The first and/or second sensor 162, 168 may be positioned to maximizethe EM telemetry signal 132 (e.g., current) that is measured. Inaddition, the first and/or second sensor 162, 168 may be positioned tomaximize the resistive path that the EM telemetry signal 132 travelsthrough. When the subterranean formation 104 is highly resistive, thefirst and/or second sensor 162, 168 may be positioned in a conductivelayer of the subterranean formation 104 below a highly resistive layer.

The sensors 144, 146, 162, 168 may be positioned in and/or configured todetect signals from a single downhole tool 120 in a signal wellbore 110or multiple downhole tools 120 in multiple wellbores 110, 160, etc. Thesensors 144, 146, 162, 168 may operate on land or in marineenvironments. The sensors 144, 146, 162, 168 may communicateunidirectionally or bi-directionally. In some embodiments, the sensors144, 146, 162, 168 may communicate with each other and/or with othercomponents of the downhole tools 120 or EM telemetry system 100 tocommunicate in a full or partial duplex manner. For example, in someembodiments, the communication channels between the sensors 144, 146,162, 168 may be used for full duplex operation and may communicatebi-directionally and simultaneously. The sensors 144, 146, 162, 168 mayuse automation, downlinking, noise cancellation, etc., and may operatewith acquisition software and/or human operators.

FIG. 2 illustrates a schematic view of a differential amplifier 200 thatmeasures the voltage difference across the sensors 162, 168, which canbe electrodes in contact with the casing 166, according to anembodiment. The signals 132, 142 measured by the first and secondsensors 162, 168 may be introduced into the differential amplifier 200to generate the voltage differential. This embodiment reduces the noisethat couples both the sensors 162, 168 (e.g., common mode noise). Asshown, the impedance from the sensors 162, 168 to the input of thedifferential amplifier may be very low (e.g., equal to the casingresistance for that section of casing 166 for the example in which thesensors 162, 168 contact the casing 166). In this embodiment, the lowsource impedance provides high noise immunity as compared to a differentembodiment that measures the differential signal between the sensor 162and a stake placed at the surface 102. The latter embodiment may havehigher impedance and also may couple the noise signals 142 from thesurface equipment 140. In at least one embodiment, the impedance of thefront end may be varied to match the resistance of the casing 166, whichmay be roughly known per unit of distance (e.g., meter).

The amplifier 200 may have a high common mode rejection ratio, whichremoves common mode noise. In addition to the common mode rejectionbenefit of multiple sensors 162, 168 in the second wellbore 160, themultiple sensors 162, 168 may provide the ability to capture the EMtelemetry signal 132 from the downhole tool 120 throughout the fullinterval.

FIG. 3 illustrates a schematic side view of the second wellbore 160having three sensors 162, 168, 172, according to an embodiment. Thethird sensor 172 may be positioned proximate to the top of the secondwellbore 160 (e.g., coupled to the casing 166, wellhead, or BOP). Thesecond and third sensors 168, 172 may be used to measure the EMtelemetry signal 132 from the downhole tool 120 when the downhole tool120 is in a first, upper interval in the first wellbore 110 (e.g., whenthe depth of the downhole tool 120 is less than the depth of the secondsensor 168). The first and second sensors 162, 168 may then be used tomeasure the EM telemetry signal 132 from the downhole tool 120 when thedownhole tool 120 is in a second, lower interval in the first wellbore110 (e.g., when the depth of the downhole tool 120 is greater than thedepth of the second sensor 168). In one embodiment, the computer system1000 may be or include a multi-channel acquisition system that uses thesignals from the sensors 162, 168, 172 to remove noise with anoise-cancelation algorithm to maximize the SNR.

FIG. 4 illustrates a schematic side view of a wellbore having an EMtelemetry tool with downhole dipoles separated by electrical gaps. Thetransmitter to the gap is one pole, while the gap to the wellhead isanother pole. The EM signal may be injected in the formation using thisdipole. The EM signal may be sensed on the surface using surface antennaor stakes. The surface antenna or stakes are inserted into the ground,such that the EM signal traveling through the drill pipe constituteshigh potential and the surface antenna constitutes low potential suchthat the surface bipole gets the signal. The process of transmitting anEM signal from downhole to the surface is referred to as EM uplink,while the transmission of EM signals from the surface to the downholetool is referred to as downlink.

The demodulation of an EM signal is affected by the signal to noiseratio (SNR) in the EM signal frequency band. Rig activity generatesunwanted electrical noise at the surface, and as drilling depthincreases, EM signal amplitudes received at the surface weakens due toattenuation, whereas surface noise amplitude remains the same. Thisleads to reduced SNR as the drilling depth increases. Once SNR dropsbelow a certain level, demodulating the EM signal at the surface maybecome very difficult.

In some embodiments, the arrangement of one or more downhole sensors,and the configuration of each downhole sensor, may reduce the effects ofsurface noise on the EM signals. For example, in some embodiments,multiple downhole sensors (i.e., receivers, electrodes, toroids, etc.)may be available for making multiple electrical contact points downhole.These multiple sensors may be configured such that during operation ofthe system, certain sensor pairs may be selected based on its impedance.For example, the sensors may be configured such that two downholesensors having a signal with the highest SNR may be selected, therebyproviding for more simplified and accurate decoding and demodulation.

FIG. 5 illustrates a schematic side view of a wellbore having an EMtelemetry tool, as well as a schematic representation of the downholesensors and electrically insulated gaps which isolate the sensors. Sucha multi-contact EM telemetry system may include multiple conductors andmay be deployed using wireline, with a MWD or LWD tool, or in any othersuitable logging conveyance. The multi-contact EM telemetry system mayhave multiple sensors, each spaced a distance apart from another. Forexample, each sensors may be 500 ft to 3000 ft apart, or 1000 ft to 2000ft apart, etc. The sensors may be different distances apart, and thedistances between each sensor may further be adjustable, either beforeor after it is deployed downhole. In some embodiments, a suitableprocessor controller, such as surface acquisition software, may monitorthe performance of the electrode pairs and dynamically choose one ormore electrode pairs based a location of the transmitter (e.g., at thebit), and based on the signal obtained at the sensors.

In accordance with the present techniques, the multi-contact EMtelemetry system may include spring loaded contact points which havecontinuous contact with the casing or open hole during its downholedeployment and operation. If an sensor pair separation is selected, thetwo sensors connected by a single conductor cable may be utilized as astandalone installation. At the rig site, the top electrode may be wiredto the two wireline conductors, reducing the overall rig setup time.

Each sensor may include mechanical wire clamp parts, electricalconnection with pressure sealing parts, insulated gap joints parts,electrical connection to centralizer, centralizer that contactsformation/casing mechanically and electrically, electrical connectionwith pressure sealing parts, and other mechanical wires clamp parts, asillustrated in FIG. 6. As illustrated in FIG. 7, mechanical wire clampparts may include cable head housing, clamps for mechanical connections,and electrical sockets with covered with rubber boot for pressuresealing. In some embodiments, by mating electrical connections,multi-conductor cable without armor may pass through the insulated gapjoint and centralizer and connected to the other electrical connectorwhich has same structure and pressure sealing function. A wire may beconnected to the insulated gap joint to contact with the centralizer.Other wires may pass through the inside diameter for use in otherelectrode. As illustrated in the schematic sideview of FIG. 8, multiplesensor connections are possible by repeating the connections andconfigurations illustrated in FIGS. 6 and 7.

In some embodiments, surface power may be delivered (e.g., via wireline)to activate a motor downhole. This motor may use linear actuationmechanisms to energize a cantilever arm to make electrical contact withthe casing or formation. To retrieve the electrode, mechanical springsmay be used to retract the arm. The cantilever arm, as illustrated inFIG. 9, may be actuated by multiple linear to radial actuationmechanisms (e.g., cam, radial outward grooves to push the arm out,etc.).

Furthermore, to further reduce the effects of surface noise, and asillustrated in FIG. 10, a downhole decoder and/or wireless transmittermay be used in some embodiments. The downhole decoder may reduce orremove noise for different deep electrode pairs and wirelessly transmitan electrode pair wellpair to the MWD computer for display. By decodingelectrical signals downhole, potential noise may be reduced or removed.The wireless transmitter may be used to select wells for deployment ofsensor arrays. For example, as illustrated in FIG. 11 representing awell pad with two observation wells, multiple sensor pairs may beinstalled in both observation wells. Depending on the drill bit depth,an electrode (and wellpair) may be selected for having a downlink oruplink signal with a suitable SNR.

In some embodiments, the electrically insulating gap sub used in the EMsystem may be configured to create a voltage difference across twoelectrically insulated elements of the sub. The gap sub may be conveyedusing wireline, slickline, or coiled tubing, such that these conveyancesmay be passed through the gap sub and a repeater may be located in thepiping string. In some embodiments, an electrical conductor may passthrough a dielectric thermoplastic material. The voltage differencebetween the two electrically insulated elements of the sub may becontrolled by applying a voltage to this electrical conductor from acavity within the gap sub. The design may be used for short range EMcommunication in an EM system.

As illustrated in FIG. 12, a gap sub may include a male sub and a femalesub which are electrically conductive, and an insulation between themale and female subs. The insulation gap may be filled withnonconductive plastic material (e.g., by injection). A probe may beconfigured in the gap sub to create a voltage difference across the gapsub through the metal centralizers in contact with the inner bore of thegap sub. A conductor channel may be created across the electricalinsulation structure, as shown in FIG. 13, between an electronic pocketon one side of the insulation and the other side of the insulation. Aninsulated conductor inside the conductor channel may control theelectrical potential of the male sub from the electronic cartridge. Asthere may be limited space between the male and female threads of themale and female subs, the relative positions of the two threads may notbe controlled precisely. In some embodiments, a groove may be cut in thefemale thread in which the channel may terminate. As illustrated in FIG.14, this may prevent the conductor from contacting both male and femalesubs at the same time, which would create a short between the twoelements of the gap sub.

Once the male and female subs are assembled together, similarly to thecurrent dry assembly process, an insulated electrical conductor may berun through the conductor channel until it contacts the male sub. Theinsulated electrical conductor may then be secured before the injectionof the dielectric thermoplastic. Once the injection is complete, theelectrical potential of the male sub may be controlled from theelectronic pocket through an insulated conductor termination, asillustrated in FIG. 15. As illustrated in FIG. 16, several conductorchannels may be created radially, if high currents are required to bepassed through.

In accordance with the present techniques, variations of the conductorchannel are possible by changing the location of the channel, inparticular the distance to the center line and the angle from the centerline anywhere from 0 to 180 degrees. The channel can be created beforeinjection or after injection. For example, FIG. 17A shows a conductorchannel created along the outer diameter of the sub, creating a grooveparallel to the axis of the sub. The electrically insulated conductormay be positioned in the groove, such that it can be accessed andsecured by potting or welding. FIG. 17B illustrates a configurationwhere the radial conductor channel is drilled through the female sub togo through the insulating structure and connect to the male sub. Thisembodiment may protect the structural integrity of the insulatingstructure on the outer diameter that is exposed to abrasion and shockwhile drilling. FIG. 17C illustrates another embodiment where an angularhole is drilled through the insulating structure. Additionally, FIG. 17Dillustrates an embodiment drilling a conductor channel afterthermoplastic injection.

In some embodiments, the methods of the present disclosure may beexecuted by a computing system. FIG. 10 illustrates an example of such acomputing system 1000, in accordance with some embodiments. Thecomputing system 1000 may include a computer or computer system 1001A,which may be an individual computer system 1001A or an arrangement ofdistributed computer systems. The computer system 1001A includes one ormore analysis modules 1002 that are configured to perform various tasksaccording to some embodiments, such as one or more methods disclosedherein. To perform these various tasks, the analysis module 1002executes independently, or in coordination with, one or more processors1004, which is (or are) connected to one or more storage media 1006. Theprocessor(s) 1004 is (or are) also connected to a network interface 1007to allow the computer system 1001A to communicate over a data network1009 with one or more additional computer systems and/or computingsystems, such as 1001B, 1001C, and/or 1001D (note that computer systems1001B, 1001C and/or 1001D may or may not share the same architecture ascomputer system 1001A, and may be located in different physicallocations, e.g., computer systems 1001A and 1001B may be located in aprocessing facility, while in communication with one or more computersystems such as 1001C and/or 1001D that are located in one or more datacenters, and/or located in varying countries on different continents).

A processor may include a microprocessor, microcontroller, processormodule or subsystem, programmable integrated circuit, programmable gatearray, or another control or computing device.

The storage media 1006 may be implemented as one or morecomputer-readable or machine-readable storage media. Note that while inthe example embodiment of FIG. 18 storage media 1006 is depicted aswithin computer system 1001A, in some embodiments, storage media 1006may be distributed within and/or across multiple internal and/orexternal enclosures of computing system 1001A and/or additionalcomputing systems. Storage media 1006 may include one or more differentforms of memory including semiconductor memory devices such as dynamicor static random access memories (DRAMs or SRAMs), erasable andprogrammable read-only memories (EPROMs), electrically erasable andprogrammable read-only memories (EEPROMs) and flash memories, magneticdisks such as fixed, floppy and removable disks, other magnetic mediaincluding tape, optical media such as compact disks (CDs) or digitalvideo disks (DVDs), BLUERAY® disks, or other types of optical storage,or other types of storage devices. Note that the instructions discussedabove may be provided on one computer-readable or machine-readablestorage medium, or may be provided on multiple computer-readable ormachine-readable storage media distributed in a large system havingpossibly plural nodes. Such computer-readable or machine-readablestorage medium or media is (are) considered to be part of an article (orarticle of manufacture). An article or article of manufacture may referto any manufactured single component or multiple components. The storagemedium or media may be located either in the machine running themachine-readable instructions, or located at a remote site from whichmachine-readable instructions may be downloaded over a network forexecution.

In some embodiments, the computing system 1000 contains one or moretelemetry module(s) 1008. The telemetry module(s) 1008 may be used toperform at least a portion of one or more embodiments of the methodsdisclosed herein (e.g., method 900).

It should be appreciated that computing system 1000 is one example of acomputing system, and that computing system 1000 may have more or fewercomponents than shown, may combine additional components not depicted inthe example embodiment of FIG. 10, and/or computing system 1000 may havea different configuration or arrangement of the components depicted inFIG. 10. The various components shown in FIG. 10 may be implemented inhardware, software, or a combination of both hardware and software,including one or more signal processing and/or application specificintegrated circuits.

Further, the methods described herein may be implemented by running oneor more functional modules in information processing apparatus such asgeneral purpose processors or application specific chips, such as ASICs,FPGAs, PLDs, or other appropriate devices. These modules, combinationsof these modules, and/or their combination with general hardware areincluded within the scope of protection of the disclosure.

As used herein, the terms “inner” and “outer”; “up” and “down”; “upper”and “lower”; “upward” and “downward”; “above” and “below”; “inward” and“outward”; “uphole” and “downhole”; and other like terms as used hereinrefer to relative positions to one another and are not intended todenote a particular direction or spatial orientation. The terms“couple,” “coupled,” “connect,” “connection,” “connected,” “inconnection with,” and “connecting” refer to “in direct connection with”or “in connection with via one or more intermediate elements ormembers.” Similarly, the term “in contact with” refers to “in directcontact with” or “in contact with via one or more intermediate elementsor members.”

The foregoing description, for purpose of explanation, has beendescribed with reference to specific embodiments. However, theillustrative discussions above are not intended to be exhaustive or tolimit the disclosure to the precise forms disclosed. Many modificationsand variations are possible in view of the above teachings. Moreover,the order in which the elements of the methods described herein areillustrate and described may be re-arranged, and/or two or more elementsmay occur simultaneously. The embodiments were chosen and described inorder to explain the principals of the disclosure and its practicalapplications, to thereby enable others skilled in the art to utilize thedisclosure and various embodiments with various modifications as aresuited to the particular use contemplated. Additional informationsupporting the disclosure is contained in the appendix attached hereto.

What is claimed is:
 1. An electromagnetic (EM) telemetry system,comprising: a measuring while drilling (MWD) display computer; an EMtransmitter in a first wellbore; an EM receiver in a second wellboreremote from the first wellbore, the EM receiver being configured toreceive signals from the EM transmitter in the first wellbore; and awireless transmitter configured to transmit signals received at the EMreceiver in the second wellbore to the MWD display computer.
 2. Thesystem of claim 1, wherein the EM transmitter is a first EM transmitterand the signals are first signals, and further comprising a second EMtransmitter in a third wellbore, and wherein the EM receiver isconfigured to receive second signals from the second EM transmitter. 3.The system of claim 1, wherein the second wellbore is offset from thefirst wellbore by between 1,000 meters and 3,000 meters.
 4. The systemof claim 1, wherein the wireless transmitter is configured to transmit adownlink EM signal to the EM receiver.
 5. The system of claim 1, whereinthe wireless transmitter is configured to transmit the signals to aremote data network.
 6. The system of claim 1, further comprising adownhole decoder connected to the EM receiver in the second wellbore,wherein the downhole decoder is configured to reduce noise of thereceived signals.
 7. The system of claim 1, wherein the EM receiver isconfigured to transmit a downhole signal to the EM transmitter.
 8. Thesystem of claim 1, further comprising an insulated cable to transmit thesignals received at the EM receiver to the wireless transmitter.
 9. Thesystem of claim 1, wherein a depth of the EM receiver is greater than orequal to a depth of the EM transmitter.
 10. A method for downholeelectromagnetic (EM) telemetry, comprising: transmitting an EM signalfrom an EM transmitter located in a first wellbore; receiving the EMsignal at an EM receiver located in a second wellbore remote from thefirst wellbore; and wirelessly transmitting the EM signal to an MWDdisplay computer from a surface wireless transmitter.
 11. The method ofclaim 10, wherein the EM signal is a first EM signal, and furthercomprising receiving a second EM signal from a third wellbore remotefrom the first wellbore and the second wellbore.
 12. The method of claim10, further comprising wirelessly transmitting an EM downlink signalfrom the surface wireless transmitter to the EM receiver.
 13. The methodof claim 10, wherein the EM signal is a first EM signal, and furthercomprising transmitting a second EM signal from the EM receiver to theEM transmitter.
 14. The method of claim 10, further comprising at leastpartially decoding the EM signal at a downhole decoder in the secondwellbore.
 15. The method of claim 10, further comprising transmittingthe EM signal from the EM receiver to the surface wireless transmitterwith a wired connection.
 16. The method of claim 10, further comprisingwirelessly transmitting the EM signal to a remote data processor. 17.The method of claim 10, further comprising at least partially decodingthe EM signal at the MWD display computer.
 18. A method for downholeelectromagnetic (EM) telemetry, comprising: at an MWD display computer,receiving a signal from a wireless transmitter located at a surfacelocation of a first wellbore, wherein: the wireless transmitter receivesthe signal from an EM receiver in the first wellbore; and the EMreceiver receives the signal from an EM transmitter located in a secondwellbore remote from the first wellbore.
 19. The method of claim 18,wherein the signal includes survey information from the second wellbore.20. The method of claim 18, wherein the MWD display computer is a remotedata processor.